Viscous oil, such as heavy oil or bitumen, residing in reservoirs that are sufficiently close to the surface may be mined.
Viscous oil residing in reservoirs that are too deep for commercial mining may be recovered by in situ processes. Commonly, viscous oil is produced from subterranean reservoirs using in situ recovery processes that reduce the viscosity of the oil enabling it to flow to the wells; otherwise, an economic production rate would not be possible. In commercial in situ viscous oil recovery processes, the temperature or pressure is modified or a solvent is added to reduce the viscosity or otherwise enhance the flow of the viscous oil within the reservoir. Such a solvent may be referred to herein simply as a “solvent”.
In certain processes, such as in SAGD (Steam Assisted Gravity Drainage), a dedicated injection well and a dedicated production well are used. The SAGD process involves injecting steam into the formation through an injection well or wells at a rate which is able to maintain a near constant operating pressure in the steam chamber. Steam at the edges of the steam chamber condenses as it heats the adjacent non-depleted formation. The mobilized oil and steam condensate flow via gravity to a separate production well located at the base of the steam chamber. An example SAGD is described in U.S. Pat. No. 4,344,485 (Butler).
In other processes, such as in CSS (Cyclic Steam Stimulation), the same well is used both for injecting a fluid and for producing oil. In CSS, cycles of steam injection, soak, and oil production are employed. Once the production rate falls to a given level, the well is put through another cycle of injection, soak, and production. An example of CSS is described in U.S. Pat. No. 4,280,559 (Best).
Steam Flood (SF) involves injecting steam into the formation through an injection well. Steam moves through the formation, mobilizing oil as it flows toward the production well. Mobilized oil is swept to the production well by the steam drive. An example of steam flooding is described in U.S. Pat. No. 3,705,625 (Whitten).
Other thermal processes include Solvent-Assisted Steam Assisted Gravity Drainage (SA-SAGD), an example of which described in Canadian Patent No. 1,246,993 (Vogel); Vapour Extraction (VAPEX), an example of which is described in U.S. Pat. No. 5,899,274 (Frauenfeld); Liquid Addition to Steam for Enhanced Recovery (LASER), an example of which is described in U.S. Pat. No. 6,708,759 (Leaute et al.); and Combined Steam and Vapour Extraction Process (SAVEX), an example of which is described in U.S. Pat. No. 6,662,872 (Gutek).
A process that can be operated thermally or non-thermally is CSDRP (Cyclic Solvent-Dominated Recovery Process), an example of which is described in Canadian Patent No. 2,349,234 (Lim).
One concern in thermal stimulation processes involving steam is the distribution of steam from horizontal wells into the formation. This is accomplished in conventional techniques by providing holes or slots in the casing. In a horizontal well which is used only for steam injection at subfracture reservoir pressures, steam distribution can be achieved by one of two means—the number and size of holes in the liner can be limited, such that at the desired steam injection rates, choked or critical (sonic) flow is achieved through the holes and equitable steam distribution at each hole location is achieved; or the target steam injection rates can be constrained such that only a minimal pressure drop occurs along the liner. Thus, the pressure gradient available for steam flow between the liner and reservoir at all points on the horizontal well is the dominant factor controlling the steam injection or production rate distribution along the well. Both of these design criteria put significant constraints on the steam injection operation. Frequently, the methodology used to achieve uniform distribution rates is to design a liner to achieve minimal pressure drops by increasing the liner diameter and limiting maximum steam injection rates, which have the disadvantages of increased cost and operational restrictions, respectively.
In a horizontal well which is used to inject steam at fracture pressures, neither of these steam distribution techniques is adequate. In a reservoir such as the Clearwater formation at Cold Lake in Alberta, Canada, the reservoir fracture pressure is typically 10 to 11 MPa. This pressure is too high to allow the critical flow design option to be successfully used. If a conventional liner were used, it is most likely that the horizontal well would fracture at only one location along the wellbore, and, in the following steam cycle, it may not be possible to move the fracture to a different portion of the wellbore.
Advantageously, the holes or slots in the well casing are also used in the production phase during which the mobile hydrocarbons flow into the well. However, particulate matter, such as sand and other formation fines, can either plug the holes or slots directly if relatively few openings are available, or they can also flow into the well with the produced hydrocarbons. Particulate matter settling inside the well can choke off sections of the well completely, thereby adversely affecting subsequent hydrocarbon production and steam injection.
In an effort to minimize the production of particulate matter with hydrocarbon fluids, well casings are often provided with a slotted liner or an external wire-wrap screen extending over a portion of the length of the horizontal portion of the well. In wire-wrap applications, holes are drilled in the well casing below the wire-wrap screens to provide an open area of about 8%. To achieve this degree of open area, hundreds of ⅜″ diameter holes are required. For example, for a typical 8⅝″ diameter pipe, 246⅜″ holes are required per foot length of pipe to give an open area of 8.4%. The ratio of screened to blank sections of pipe is determined by the average % open area one wants for the application. Typically, the ratio is set to allow 1.5 to 3% of the base pipe to be open area. This relatively large open area is provided to minimize pressure drop constraints on, and velocities of, the fluids being produced from the reservoir. An external wire-wrap screen is then placed around the casing to reduce the flow of particulate matter through the holes. Slotted liners typically have corresponding open areas provided with the slots cut into the liner. In these designs, essentially no flow restrictions occur as the fluids pass through the slots or wire-wrap screen assemblies. Corresponding high velocities may expose the liner to erosion by the entrained sand.
An example of a known technique for distributing steam is described in U.S. Pat. No. 5,141,054 (Alameddine et al.) which relates to a limited entry steam heating method for distributing steam from a closed-end tubing in a perforated well casing. The tubing string has perforations to achieve critical flow conditions such that the steam velocity through the holes in the close-end tubing reaches acoustic speed. However, the large annulus flow area, plus the still large number of holes in the well casing, compromise the distribution of steam into the formation. Accordingly, critical flow is not maintained in the wellbore annulus and through the casing into the reservoir, so that the desired steam distribution control is lost.
Canadian Patent No. 2,219,513 (Bacon et al.) (“Bacon”) describes a system and method for distributing steam and producing hydrocarbons through a well, to enhance steam distribution during a thermal stimulation phase, and to reduce the influx of particulate matter during a production phase, and where steam injection may occur at pressures below, up to, or exceeding the reservoir fracture pressure.
Bacon describes, in one aspect, a system for distributing steam in a steam injection phase and for producing hydrocarbon fluids in a production phase from a horizontal well in a reservoir, comprising: a base pipe having a plurality of spaced-apart orifices in the wall thereof; a plurality of second pipe sections disposed around the base pipe, and means for spacing each second pipe section from the base pipe to form an annulus between the base pipe and each second pipe section; each second pipe section having distribution means for distributing steam in the steam injection phase and for minimizing influx of particulate matter in the production phase; each second pipe disposed around a portion of the base pipe such that at least a portion of the distribution means is disposed over an orifice; whereby steam flowing through the base pipe flows outwardly through the plurality of orifices and is distributed outwardly to the reservoir through the distribution means during the steam injection phase; and, in the production phase, hydrocarbon fluids flow inwardly through the distribution means to the orifices and into the base pipe.
The system of Bacon provides enhanced steam distribution and enhanced hydrocarbon production, even though the criteria for the two phases are in opposition. In previous systems, the size and number of holes is large to reduce the pressure drop across the holes during the production phase. However, well casings used specifically for injection ideally have a reduced number of holes to increase the pressure drop of the steam through the holes.
Bacon uses a common set of holes for both steam distribution and hydrocarbon production phases and therefore a well can be used for thermal stimulation and/or hydrocarbon production phases.
FIGS. 1 to 3 herein are based on Bacon's FIGS. 1 to 3. Referring to FIG. 1, the system of Bacon has a base pipe 12 with an orifice 14 in the pipe wall. A second pipe 16 is disposed over a section of the base pipe 12 having the orifice 14. The second pipe 16 has a collar 18 and sections of wire-wrap screen 22 connected to either side of the collar 18 by connector rings 24. The second pipe 16 is disposed over the base pipe 12 such that the collar 18 is positioned over the orifice 14. The wire-wrap screen sections 22 are secured at the opposite end of the base pipe 12 by boss rings 26.
As shown more clearly in FIG. 2, the collar 18 is spaced from the base pipe 12 by rods 28 or the like to provide an annulus.
As shown more clearly in FIG. 3, support ribs 32 are used to space the wire-wrap screen sections 22 from the base pipe 12 to form an annulus in communication with the annulus between the base pipe 12 and the collar 18.
Alternatively, the collar 18 can be connected on either side to a section of slotted liner or other sand control device (not shown), instead of a wire-wrap screen.
Further, the collar 18 may be omitted. If, in Bacon's proposed application, potential erosion of the screens is not a concern, the collar may be replaced with a section of wire-wrap screen or other similar element.
The number of orifices 14 in a length of base pipe 12 is reduced in the system of the Bacon, as compared with conventional techniques, to increase the pressure drop across the orifices 14. The collar 18 and the wire-wrap screen sections 22 allow the steam to exit uniformly across the wire-wrap screen section 22 into the reservoir. The collar 18 preferably has a wall thickness which can withstand the force of the steam impacting the collar 18. Where the velocity of the steam is lower, the steam will distribute along the wire-wrap screen without the need for the collar.
In a situation in which steam injection at the design injection rates for the specific application is occurring at pressures less than the reservoir fracture pressure, the higher the pressure drop ratio is between that through the orifice 14 and that along the base pipe 12, the smaller will be the steam maldistribution occurring along the base pipe 12. Variations in reservoir quality and oil saturation along and external to the base pipe 12 will result in differences in the transmissibility of the steam at each orifice 14 location. In areas of the high steam transmissibility, the steam rate through the orifice 14 will want to increase. However, as the steam rate increases, the pressure drop through the orifice 14 also increases. This will reduce the maximum injection rate achievable through orifice 14. In areas with low steam transmissibility, the steam rate through the orifice 14 will want to decrease. However, as the steam rate decreases, the pressure drop through the orifice 14 also decreases. This will increase the minimum injection rate achievable through the orifice 14. Application of this design feature helps compensate for variations in reservoir quality along the base pipe 12 and thus, assists in improving the steam distribution into the reservoir along the base pipe 12. To ensure that it is not possible to fracture the reservoir at an orifice 14 where steam transmissibility is low, the steam pressure within the base pipe 12 should be maintained at less than the reservoir fracture pressure.
In a situation in which steam injection at the design injection rates for the specific application is occurring at or above reservoir fracture pressure, it is also necessary to ensure that pressure drop across the orifice 14 is larger than the expected variation in the reservoir fracture pressure along the base pipe 12. This will ensure that the steam exiting each orifice 14 along the base pipe 12 is capable of fracturing the reservoir at that location. Steam maldistribution can be reduced by ensuring that the orifice 14 pressure drop at the design injection rates is significantly higher than the expected variability in the reservoir fracture pressure along the base pipe 12.
In use, sections of the base pipe 12 are joined together to provide a predetermined number of orifices 14 along the length of the horizontal well. For example, to inject 1,500 m3/d (cold water equivalent) of 11 MPa steam (70% quality) into a reservoir, twenty ½″ diameter holes would be required to achieve a pressure drop of 500 kPa across the orifices 14. The desired pressure drop is dependent on the reservoir fracture pressure and the variations thereof along the length of the well. The pressure drop across the orifices 14 is affected by the number and size of holes available for flow and the spacing thereof, and the diameter of the base pipe 12.
In conventional systems, the open area was too large to create a pressure constraint on fluids injected or produced. In Bacon, the deflection of high pressure steam through a limited number of holes creates good distribution during injection and the entry points available across the wire-wrap screen sections 22 allow for low pressure drop during production. The ½″ diameter holes of the system of Bacon can be spaced 25 m apart, as compared to the 246⅜″ diameter holes per foot in a conventional system. For example, twenty ½″ diameter holes in a 500 m length 5½″ diameter pipe represents an open area of 0.0012%. A person of ordinary skill in the art will understand that the structural integrity of a base pipe having an open area of 0.0012% is significantly greater than a conventional pipe having an open area of 8.4%, as discussed earlier. The cost of the base pipe of Bacon is reduced significantly, because the number of holes which must be cut in the base pipe is reduced drastically, and the wall thickness of Bacon need not be as great to support the number of holes being cut.
Preferably, the number and size of orifices 14 in the base pipe 12 is such that there is provided an open area of less than 0.5%. More preferably, the open area in the base pipe 12 is less than 0.1%. Even more preferably, the open area in the base pipe 12 is less than 0.01%.
For example, by spacing the twenty ½″ diameter holes equally along a 500 m long 5½″ diameter base pipe 12, the level of steam maldistribution (defined as 0.5 times the ratio of the steam injection rate through the first and last holes) when injecting 1,500 m3/d of high pressure steam (70% quality) into a reservoir with a reservoir fracture pressure of 10 MPa would be less than 10%. In this example, the pressure drop is less than 50 kPa across the orifices in the production phase when the production rate is 300 m3/d of liquids and 21,000 sm3/d of wet vapors and the near wellbore reservoir is 500 kPa. This example illustrates that excellent distributions of both injected steam and produced fluids can be achieved through correctly sized and distributed orifices.
Bacon's system can be set-up, for example, such that a 1 meter long collar is positioned over the orifice 14 and is connected to a 3 meter long wire-wrap screen on either side thereof. As a result of the reduced number of orifices, the steam exits the base pipe 12 at each orifice 14 and the wire-wrap screens 22 on either side of the collar 18 effectively distribute the steam into the reservoir.
In a CSS process, steam is injected into the base pipe 12 and exits through the orifices 14. Steam is deflected off the collar 18 to the wire-wrap screen sections 22 for distribution into the reservoir. Heat is transferred to the reservoir to mobilize the hydrocarbon fluids. In the production phase, steam injection is discontinued and mobilized hydrocarbon fluids are allowed to flow to the distribution means which act to screen particulate matter from the fluid. Hydrocarbon fluid then travels in the annulus between the second pipe 16 to the orifice 14 into the base pipe 12 and is pumped to surface. Preferably, the steam injection and hydrocarbon fluids production steps are repeated cyclically.
In a SAGD process, steam is injected into the base pipe 12 and exits through the orifices 14. Steam is deflected off the collar 18 to the wire-wrap screen sections 22 for distribution into the reservoir. The number of orifices is constrained, such that the pressure drop through the orifices 14 is larger than the pressure drop along the liner itself. This ensures the equal distribution of steam along the injector and that either longer injectors and/or smaller diameter liners can be utilized. Heat is transferred to the reservoir to mobilize the hydrocarbon fluids. The mobilized hydrocarbon fluids drain to a production well where it is pumped to the surface. The production well may also comprise a base pipe 12 having orifices 14 with wire-wrap screen sections 22 disposed around the base pipe 12, and an annulus between the base pipe 12 and the wire-wrap screen sections 22. Mobile hydrocarbon fluids then flow through the annulus to the orifice 14 and into the base pipe. The number of orifices is constrained such that the pressure drop through the orifices 14 is larger than the pressure drop through either the wire-wrap screen sections 22 or along the liner itself. Shifting of the key flow restriction away from the wire-wrap sections 22 prevents excessive fluid velocities from mobilizing sand and thus eroding the screens. Having the pressure drops through the orifices 14 much larger than the pressure drop along the liner, ensures that the pressure drop within the liner does not adversely affect the inflow performance of the production well and thus, more uniform hydrocarbon fluid influx occurs along the wellbore. This design feature will allow the utilization of longer producers and/or smaller diameter producers. A second benefit of this design feature is that at sections of the wellbore which are coning steam from the steam chamber, the presence of the limited number of orifices restricts the rate which steam can enter the production wellbore. This reduces steam production without adversely affecting the hydrocarbon fluid production from the remaining section of the wellbore.
In a SF process, steam is injected into the base pipe 12 and exits through the orifices 14. Steam is deflected off the collar 18 to the wire-wrap screen sections 22 for distribution into the reservoir. The number of orifices is constrained such that the pressure drop through the orifices 14 is larger than the pressure drop along the liner itself. This ensures the equal distribution of steam along the injector and that either longer injectors and/or smaller diameter liners can be utilized. Heat is transferred to the reservoir to mobilize the hydrocarbon fluids. The mobilized hydrocarbon fluids are displaced to a production well where it is pumped to the surface. The production well may also comprise a base pipe 12 having orifices 14 with wire-wrap screen sections 22 disposed around the base pipe 12 and an annulus between the base pipe 12 and the wire-wrap screen sections 22. Mobile hydrocarbon fluids then flow through the annulus to the orifice 14 and into the base pipe 12. The number of orifices is constrained such that the pressure drop through the orifices 14 is larger than the pressure drop through either the wire-wrap screen sections 22 or along the liner itself. Shifting of the key flow restriction away from the wire-wrap sections 22 prevents excessive fluid velocities from mobilizing sand and thus eroding the screens. Having the pressure drops through the orifices 14 much larger than the pressure drop along the liner ensures that the pressure drop within the liner does not adversely affect the inflow performance of the production well, and thus, either longer producers and/or smaller diameter producers can be utilized.
A key limitation of screened completions is that they tend not to be mechanically robust. Screens are relatively easily damaged during installation. They are also susceptible to erosion when steam or gas influx occurs rapidly in a concentrated area. This latter limitation also applies to slotted liners but to a lesser extent. Even a single localized failure in one screen along a well can render part or all of the well ineffective because sand influx into the well can effectively block flow. In Bacon's system, where a screen becomes damaged, even in only one location, sand will pass through the damaged portion of the screen, through the round orifice in the base pipe, and into the well. As a result, operational processes are typically constrained to limit the risk of a failure. For example, during start-up of SAGD well pairs, a relatively gentle process is typically employed so that steam breakthrough in a localized region will not fail a screen. A more robust completion design with injection and inflow control would allow much more rapid and aggressive start-up procedures for SAGD well pairs.